1. Field of the Invention
The present invention relates to epoxy resin compositions. The present invention also relates to methods of treating subterranean formations using consolidatable epoxy resin-coated particulate materials.
2. Description of the Prior Art
Consolidatable epoxy resin-coated particulate materials have been used heretofore in various well treatment operations. Consolidatable epoxy resin-coated sands have been used, for example, for gravel packing, for the development of controlled permeability synthetic formations within subterranean zones, for frac-pack operations, and as proppant materials in formation fracturing operations. Due to their desirable permeability and compressive strength characteristics, consolidatable epoxy resin-coated particulate materials are especially well-suited for treating semiconsolidated and unconsolidated formations which contain loose or unstable sands.
As used herein, the term "consolidatable epoxy resin-coated particulate material" refers to a particulate material which is coated with an uncured or only partially cured epoxy resin composition. Typically, the consolidatable epoxy resin-coated particulate material will be injected into a subterranean zone using procedures whereby the epoxy resin does not substantially harden until after the particulate material has been delivered to a desired location within the formation. The consolidatable epoxy resin-coated particulate material will typically harden within the formation to form a hard, consolidated, permeable mass.
Those skilled in the art have commonly used gravel packs to control particulate migration in producing formations. A gravel pack will typically consist of a mass of particulate material which is packed around the exterior of a screening device, said screening device being positioned in an open hole or inside a well casing. Examples of typical screening devices include wire-wrapped screens and slotted liners. The screening device will typically have very narrow slots or very small holes formed therein. These holes or slots are large enough to permit the flow of formation fluid into the screening device but are too small to allow the particulate packing material to pass therethrough. In conjunction with the operation of the holes or slots formed in the screening device, the particulate packing material operates to trap, and thus prevent the further migration of, formation sand and fines which would otherwise be produced along with the formation fluid.
Hydraulic fracturing techniques are commonly used to stimulate subterranean formations in order to enhance the production of fluids therefrom. In a conventional hydraulic fracturing procedure, a fracturing fluid is pumped down a well bore and into a fluid-bearing formation. The fracturing fluid is pumped into the formation under a pressure sufficient to enlarge natural fissures in the formation and/or open up new fissures in the formation. Packers can be positioned in the well bore as necessary to direct and confine the fracturing fluid to the portion of the well which is to be fractured. Typical fracturing pressures range from about 1,000 psi to about 15,000 psi depending upon the depth and the nature of the formation being fractured.
Fracturing fluids used in conventional hydraulic fracturing techniques include: fresh water; brine; liquid hydrocarbons (e.g., gasoline, kerosene, diesel, crude oil, and the like) which are viscous or have gelling agents incorporated therein; gelled water; and gelled brine. The fracturing fluid will also typically contain a particulate proppant material. The proppant flows into and remains in the fissures which are formed and/or enlarged during the fracturing operation. The proppant operates to prevent the fissures from closing and thus facilitates the flow of formation fluid through the fissures and into the well bore.
Frac-pack operations are primarily used in highly unconsolidated formations to facilitate fluid recovery while preventing particulate migration. A frac-pack operation typically embodies the features of both a fracturing operation and a gravel packing operation. Preferably, the unconsolidated formation is initially fractured using a proppant-laden fracturing fluid. The proppant material deposits in the fractures which are formed during the fracturing operation. Due to the highly unconsolidated nature of the formation, the fractures produced during the fracturing step will typically be substantially wider and shorter than the fractures produced when fracturing consolidated formations. After a desired degree of fracturing is achieved, additional proppant material is tightly packed in the well bore. The additional proppant material will typically be held in place in the well bore by (a) packing the proppant material around a gravel packing screen and/or (b) consolidating the proppant material by means of a resin coating.
Examples of particulate materials commonly used for gravel packing and frac-pack operations and as fracturing proppants include: sand; glass beads; nut shells; metallic pellets or spheres; gravel; synthetic resin pellets or spheres; gilsonite; coke; sintered alumina; mullite; like materials; and combinations thereof.
Well treatment methods utilizing consolidatable epoxy resin-coated particulate materials are disclosed, for example, in U.S. Pat. No. 5,128,390. The entire disclosure of U.S. Pat. No. 5,128,390 is incorporated herein by reference.
U.S. Pat. No. 5,128,390 discloses a method for continuously forming and transporting consolidatable resin-coated particulate materials. In the method of U.S. Pat. No. 5,128,390, a particulate material (e.g., sand) and a hardenable epoxy resin system are continuously mixed with a stream of gelled carrier liquid. The resulting continuous composition is delivered to and/or injected into a desired subterranean zone. As the continuous mixture flows down the well tubing toward the subterranean zone, the composition ingredients are mixed such that the gel-suspended particulate material is thoroughly coated with the hardenable epoxy resin system. After being placed in the subterranean zone, the epoxy resin composition is allowed to harden whereby the resin-coated particulate material forms a hard, permeable, consolidated mass.
The hardenable epoxy resin composition used in the method of U.S. Pat. No. 5,128,390 is generally composed of: a polyepoxide resin carried in a solvent system; a hardening agent; a coupling agent; and a hardening rate controller. The hardening agent used in the method of U.S. Pat. No. 5,128,390 is either (a) an amine, a polyamine, an amide and/or a polyamide dissolved in a suitable solvent or (b) a liquid eutectic mixture of amines diluted with methanol.
Epoxy resin system curing agents currently used in the art typically contain 4,4'-methylenedianiline (MDA). MDA is a multifunctional hardening agent which provides desirable cured resin properties. However, since MDA is a carcinogen, costly and tedious procedures must be used in order to monitor worker exposure and to protect workers from overexposure. Thus, a need presently exists for an epoxy resin system hardening agent which provides cured resin properties at least comparable to those provided by MDA but which is also nonhazardous.
As will also be understood by those skilled in the art, a need presently exists for epoxy resin system hardening agents which provide faster curing times without sacrificing resin performance. In some fracturing operations, for example, the proppant material is subjected to substantial formation stresses. These stresses can operate to crush a substantial amount of the proppant material and thereby reduce the conductivity of the proppant bed. The presence of a cured resin coating on the proppant material strengthens the proppant material and protects it from formation stresses. Consequently, the achievement of a more rapid curing rate would accelerate the process by which the protective coating is formed on the proppant material and thereby reduce the amount of proppant crushing which occurs.
As will be further appreciated by those skilled in the art, a need presently exists for a means of eliminating the necessity of using curing accelerators in wells having low bottom hole temperatures. Currently, the use of one or more accelerators in such wells is necessary in order to achieve satisfactory curing rates. However, curing accelerators typically produce an undesirable degree of plasticization in the cured resin system. Curing accelerators also typically operate to undesirably lower the glass transition temperatures of cured resin systems.